Mobile gas separation unit

ABSTRACT

The mobile gas separation unit is transportable from well site to well site. The mobile gas separation unit will separate CO 2  from natural gas at the well site where the natural gas is produced. The CO 2  may be a part of a fracturing fluid that is used to fracture the formation from which natural gas is to be produced. The CO 2  will be produced up the Well with the natural gas rather than venting or flaring the gas stream that includes the CO 2  in the atmosphere. The mobile gas separation unit will separate CO 2  from the gas stream so that a sales gas stream can be communicated to a natural gas sales pipeline or gathering system.

BACKGROUND OF THE INVENTION

This invention relates to a method for separating CO₂ from a gas stream and more specifically to separating CO₂ gas from a gas stream including natural gas produced from a downhole formation at a well site.

It is well known in the oil and gas industry that wells drilled to intersect one or more subterranean hydrocarbon-producing formations are treated in a variety of ways for various purposes including to increase production from the formation(s). One well-known treatment procedure comprises fracturing wells to increase the deliverability of a formation. Fracturing of a formation is generally accomplished by injecting a fracturing fluid into the formation via the wellbore and applying sufficient pressure to initiate a fracture in the formation. Fracturing fluid may also be referred to as a stimulation fluid. Carbon dioxide (CO₂), is often used in fracturing fluids, particularly in a natural gas bearing formation. The amount of CO₂ used to fracture a formation will vary depending upon a variety of factors, including, but not limited to, the thickness of the formation, nature of the formation and the desired fracture length. In most cases, large quantities of CO₂ are used. Propping agents, also referred to as proppants, may also be displaced into the induced fracture. The proppants will hold the fractures open after pressure on the formation is released. Generally, after the hydrocarbon-bearing formation has been fractured, there is a time period in which fracturing fluid is produced through the well to the surface, along with hydrocarbons from the formation. This time period may be referred to as a flow-back or cleanup stage in which the stimulation fluids are recovered from a well. Hydrocarbons, for example, natural gas, will also be produced, during the flow-back stage. If the fluid used to fracture the formation includes CO₂, the gas produced during the cleanup stage may be contaminated with high concentrations of CO₂ gas. Purchasers of natural gas have limits with respect to the amount of CO₂ content that may exist in a gas stream intended for sale. Natural gas that is contaminated with an unacceptable amount of CO₂ is typically vented or flared to the atmosphere until the CO₂ content in the gas stream diminishes to a point that is acceptable to the natural gas purchaser. During the cleanup stage large volumes of natural gas are lost to the atmosphere. There is no known economical way to separate the CO₂ used in a fracturing fluid from the natural gas produced during the flow-back stage at the well site so that the natural gas produced during the flow-back stage may be sold rather than lost to the atmosphere.

SUMMARY OF THE INVENTION

The current invention is directed to a method of producing natural gas from a subterranean formation, and more specifically to a method for optimizing production from a subterranean producing formation by capturing natural gas produced during the flow-back stage of a well rather than venting or flaring the natural gas to the atmosphere. The method may comprise treating a downhole producing formation with a treating fluid that includes at least CO₂. The treatment method may comprise fracturing the downhole formation with a fracturing fluid that includes CO₂ to improve production of hydrocarbon fluids including natural gas from the downhole formation. The stream produced from the well, which during the flow-back stage may include the treating fluid and hydrocarbon fluids may be referred to as a production stream.

Liquids and solids may be separated from the production stream to form a production gas stream, and a mobile separation unit may be transported to the well site to separate CO₂ from the production gas stream at the well site. The mobile separation unit may separate the production gas stream into a first gas stream containing a lower CO₂ concentration than the production gas stream and a second gas stream containing a higher CO₂ concentration than the production gas stream. The first gas stream, which may be referred to as a sales gas stream, will include natural gas and will have a concentration of CO₂ that is acceptable to a natural gas purchaser, and will likely be less than 5 percent and will preferably be less than 3 percent.

The mobile separation unit will be utilized to separate CO₂ from the production gas stream until the CO₂ concentration in the production gas stream (i.e., the gas stream as it exists prior to the time it enters the mobile separation unit) is at an acceptable level and thus, is preferably less than 3 percent. Once the CO₂ concentration in the production gas stream is at an acceptable level, the mobile separation unit may be transported from the well site and housed at a storage location or may be immediately moved to a second well site and used in accordance with the method described herein for separating CO₂ used in a fracture treatment process from natural gas produced from a well. The mobile separation unit may therefore comprise a skid mounted mobile separation unit that is small enough in size and weight so that it may be placed on a trailer and transported over roadways from well site to well site.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a well site that has been drilled for the production of natural gas where CO₂ has been used as a fracturing fluid to fracture a hydrocarbon-bearing formation.

FIG. 2 is a schematic diagram of a mobile gas separation unit mounted to a trailer.

FIG. 3 shows a hydrocarbon-bearing formation intersected by a well.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

The current invention is directed to a method of producing natural gas from a subterranean formation intersected by a wellbore extending from the surface of the earth through the formation, and more particularly to a method of optimizing production of natural gas from a well. The method generally comprises fracturing the formation with a treating fluid that includes at least carbon dioxide (CO₂) and flowing a stream that includes treating fluid and natural gas from the formation through the well to the surface. The stream flowing from the well may be referred to as a production stream. Liquids and solids are removed from the production stream to form a production gas stream that will contain at least natural gas and CO₂. Typically, the CO₂ will be injected as a liquid, and may be mixed with other fluids. The CO₂ will flow from the well as a gas. A mobile gas separation unit may be transported to the well site, and the method may further comprise separating CO₂ from the production gas stream at the well site with the mobile separation unit to form a gas stream with a low concentration of CO₂. The production gas stream preferably has a low enough concentration of CO2 gas to be saleable to a natural gas purchaser.

FIGS. 1 and 3 schematically show a well site 5 with a mobile, or transportable separation unit 10 at the well site. Well 15 has been drilled from the surface 18 to intersect a downhole hydrocarbon-producing formation 20, from which hydrocarbons, for example, natural gas may be produced. Well 15 may comprise wellbore 22 having a casing 25 cemented therein. Hydrocarbons may be produced up casing 25 or as is known in the art may be produced through a production tubing, such as production tubing 30. Casing 25 may be perforated to create perforations 32. Hydrocarbon fluids from formation 20 will be communicated into casing 25 through perforations 32 so that hydrocarbon fluids may be produced to the surface. Fluid from formation 20 may be produced at well site 5 using equipment known in the art. It is understood that FIGS. 1 and 3 are schematic representations, and equipment known in the art is used to produce fluids to associated well surface 18 at well site 5. The fluids produced to the surface may be referred to as a production stream, or production fluids. At the surface, the production stream may be communicated to a piping system represented by a flow line 36 in FIG. 1, and directed to a separation system 38. Separation system 38 may be, for example, a two-phase separator of a type known in the art used to separate liquids and/or solids from a gas stream. If any solids are produced with the production stream, those solids will likely comprise a small amount of proppant.

The gas stream leaving separation system 38 is substantially a dry gas stream that may include very small amounts of trace liquids. As is known in the art, additional separators may be used to make certain that all liquids are removed from the production stream. Thus, separation system 38 may include more than one separator. The gas stream exiting separation system 38 will be a dry gas stream, and may be referred to as a production gas stream. The production gas stream may be, for example, a natural gas stream produced from the hydrocarbon-producing formation that can be communicated to a gathering system or a natural gas sales pipeline. The solids and liquids are generally directed from separation system 38 to a holding vessel through a piping system represented by flow line 42.

There are limitations on the impurities that can be present in the natural gas, and in some instances the limitations are placed on natural gas producers by purchasers of natural gas. One particular limitation is directed to the amount of CO₂ that can be present in the production gas stream. If the CO₂ concentration is at an unacceptable level, the natural gas is not saleable. Because wells drilled for production of natural gas are often treated with CO₂, the production stream may have, for a period of time, a level of CO₂ that is too high. For example, CO₂ may be used as in a fracturing fluid to fracture formation 20. Fracturing fluid may be communicated through well 15 and into formation 20 through perforations 32. The amount of CO₂ utilized to fracture the formation will vary depending upon a number of factors including but not limited to the thickness of the formation, the length of the desired fracture, and whether a single or multiple formations are being treated. By way of example only, it would not be unusual to pump about 100 tons of CO₂ into a downhole formation with a thickness of between approximately twenty to thirty feet to create fractures with a length of about 200 to 300 feet. In many cases several hundred tons of CO₂ are utilized to treat formations intersected by a well. Pressure is generally applied to urge the fracturing fluid into the formation, or formations, to create the desired fractures. Proppants may also be displaced into the well to hold the fractures open.

After the well has been subjected to the fracturing treatment and pressure on the well is released, CO₂ gas will be produced up the well to the surface 18 along with natural gas from the formation or formations. The production stream from the formation, which may include liquids, CO₂ gas and natural gas will pass through flow line 36 into separation system 38. Typically, liquids and solids are separated from the production stream in separation system 38, and the production gas stream is communicated into a piping system represented by flow line 40. During the initial stages of production, the fracturing fluid, specifically CO₂ gas, will be produced along with natural gas. As set forth herein, this stage may be referred to as the flow-back, or cleanup stage. During the flow-back stage, the concentration of CO₂ in the production gas stream will generally be at an unacceptably high level, so the natural gas cannot be delivered to a natural gas sales pipeline or a gathering system. In the current state of the art, the production gas stream flowing in flow line 40 must therefore be vented, or flared, until the CO₂ level in the production stream is at the desired level, which is less than 5 percent, and preferably less than 3 percent, and more preferably about 2 percent or less. The concentration of CO₂ in the production gas stream in flow line 40 is monitored until the production gas stream has an acceptable concentration of CO₂. It is not unusual for the production gas stream to be vented or flared for a period of several days, or even several weeks until the concentration of CO₂ in the production gas stream leaving separation system 38 is at a low enough concentration to be accepted by a gas purchaser.

In the current invention the production gas stream from separation system 38 is directed through flow line 40 to mobile gas separation unit 10. Mobile gas separation unit 10 will separate the production gas stream into first and second gas streams. The first gas stream may be directed through a piping system represented by flow line 44 and the second gas stream may be communicated from the mobile separation unit 10 through a piping system represented by flow line 46 in FIG. 1. The concentration of CO₂ in the first gas stream is less than the concentration of CO₂ in the production gas stream flowing through flow line 40. The CO₂ concentration in the first gas stream will be at a desired level, for example less than 5 percent, and preferably less than 3 percent, and more preferably about 2 percent. The first gas stream will meet the requirements of gas purchasers and thus is acceptable for purchase so that flow line 44 may be connected to a natural gas sales pipeline to direct the natural gas to a purchaser, or communicated to a gathering system. The second gas stream has a higher concentration of CO₂ than the production gas stream in flow line 40 and will be communicated to a piping system represented by flow line 46. The second gas stream will be vented to the atmosphere or may be directed as desired for a later desired use. The production gas stream flowing through flow line 40 may be continuously monitored and communicated into mobile separation unit 10 during the flow-back or cleanup stage until such time as the concentration of CO₂ in the gas stream in flow line 40 dissipates and reaches the desired level. When the CO₂ level in the production gas stream in flow line 40 reaches the desired level, the production gas stream can be communicated directly to a natural gas sales pipeline or gathering system.

When the production gas stream in flow line 40 is at a desired level, mobile separation unit 10 may be moved to another well site and used in the same manner described herein. Mobile separation unit 10 is preferably a skid mounted mobile separation unit 10 and thus includes skids 48. The overall size of skid mounted mobile separation unit 10 is such that it can be mounted to a trailer 50 and driven from well site to well site and used to separate CO₂ from a production gas stream so that the gas stream exiting the mobile separation unit 10 has a CO₂ concentration acceptable to gas purchasers. Generally, the maximum size of a skid that can be trailered is approximately 102 inches wide, eight feet tall and forty feet long. The maximum weight is approximately 50,000 pounds. Thus, such dimensions are the maximum dimensions for skid mounted mobile separation unit 10. Preferably, however, mobile separation unit 10 is much smaller than the maximum acceptable size set forth herein. Mobile separation unit 10 is preferably a self-contained unit that can be transported on a single trailer, and requires minimal assembly, other than making connections to piping systems, at the well site. In other words, the mobile separator 10 is preferably a unit that is a stand-alone unit that can be moved on a single trailer from well site to well site to separate CO₂ used as a fracturing fluid from natural gas produced from a well.

Utilizing the method of the current invention creates an economic advantage, and provides for the optimization of production of natural gas in wells where CO₂ is used as a fracturing fluid. Natural gas that normally would be lost may be captured and sold, which creates both an economic and an environmental advantage. For example, a well that was treated with approximately 200 tons of CO₂ as a fracturing fluid, initially had a production gas stream flow rate of approximately 2 MMSCFD, during the flow-back stage. The production gas stream was vented for a period of 20 days. After 20 days, the CO₂ concentration was at a low enough level, about 2%, so that the natural gas could be sold. During the time the production gas stream was vented, approximately 50 MMSCF of natural gas was lost. Utilizing the current method, the gas lost to the atmosphere could have been sold.

Thus, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims. 

1. A method of producing natural gas from a subterranean formation intersected by a wellbore extending from a well surface at a well site comprising: fracturing the formation with a treating fluid that includes at least CO₂; flowing a production stream to the surface, the production stream comprising CO₂ along with hydrocarbon fluids including at least natural gas to the well surface; transporting a mobile separation unit to the well site; and separating CO₂ from the production stream at the well site with the mobile separation unit.
 2. The method of claim 1, further comprising removing liquids from the production stream to form a production gas stream prior to the separating step.
 3. The method of claim 2, wherein the separating step comprises separating the production gas stream into a first gas stream and a second gas stream with the mobile separation unit, wherein the concentration of CO₂ in the first gas stream is lower than the concentration of CO₂ in the production gas stream, and the concentration of CO₂ in the second gas stream is higher than the concentration of CO₂ in the production gas stream.
 4. The method of claim 2, further comprising delivering a gas stream from the mobile separation unit to a natural gas sales pipeline after the separating step.
 5. The method of claim 2, wherein the separating step comprises separating the production gas stream into first and second gas streams, the first gas stream comprising less than 3 percent CO₂.
 6. The method of claim 1, further comprising moving the mobile separation unit from the well site to a second well site to separate CO₂ from a stream flowing from a wellbore at the second well site.
 7. The method of claim 6, wherein the moving step occurs after the CO₂ concentration in the production gas stream is at or below a level specified by a purchaser of the natural gas.
 8. The method of claim 6, wherein the moving step occurs after the CO₂ concentration in the production gas stream is less than about 3 percent.
 9. A method of removing CO₂ from a production stream comprising at least CO₂ and natural gas produced from a formation intersected by a wellbore extending from a well surface at a well site comprising: transporting a mobile separation unit to the well site; removing liquids from the production stream to form a production gas stream; communicating the production gas stream to the mobile separation unit; and removing CO₂ from the production gas stream to form a sales gas stream having a CO₂ concentration less than the CO₂ concentration in the production gas stream.
 10. The method of claim 9, wherein the concentration of CO₂ in the sales gas stream is less than about five percent.
 11. The method of claim 9, wherein the concentration of CO₂ in the sales gas stream is less than about three percent.
 12. The method of claim 9, further comprising delivering the sales gas stream to a natural gas sales pipeline.
 13. The method of claim 9, wherein the CO₂ comprises CO₂ used to treat the formation.
 14. The method of claim 13, wherein the treatment comprises fracturing the formation.
 15. The method of claim 9, further comprising mounting the mobile separation unit to a trailer and moving the mobile separation unit to a second well site.
 16. A method for optimizing production from a wellbore extending between a downhole producing formation and an associated well surface comprising: treating the downhole producing formation with a treating fluid that includes CO₂ to improve production of hydrocarbon fluids including natural gas from the downhole producing formation; flowing a stream of the treating fluid and hydrocarbon fluids including natural gas from the downhole producing formation through the wellbore to the well surface; separating liquids from the stream of treating fluid and hydrocarbon fluids at the well surface to form a production gas stream including at least CO₂ gas and natural gas; and separating the production gas stream at the well surface into first and second gas streams, the first gas stream having a higher natural gas to CO₂ ratio than the production gas stream and the second stream having a lower natural gas to CO₂ ratio than the production stream.
 17. The method of claim 16, wherein the concentration of CO₂ gas in the first gas stream is less than three percent.
 18. The method of claim 16, further comprising directing the first gas stream to a natural gas gathering system.
 19. The method of claim 16, further comprising directing the first gas stream to a natural gas sales pipeline.
 20. The method of claim 16, further comprising using a mobile gas separator at the associated well surface to separate the production gas stream into the first gas stream and the second gas stream.
 21. A method for optimizing production of natural gas at a well site from a downhole producing hydrocarbon formation comprising: injecting treating fluids including CO₂ through at least one wellbore into the hydrocarbon producing formation to increase fluid flow from the hydrocarbon producing formation; flowing fluid including CO₂ and natural gas from the hydrocarbon formation through the at least one wellbore to an associated well surface at the well site; separating liquid from the fluid at the well surface; directing all gases from the fluid, including natural gas and CO₂, to a gas separation unit; removing CO₂ gas from the gases; and directing natural gas to a natural gas sales pipeline.
 22. The method of claim 21, further comprising transporting the gas separation unit to the well site to perform the removing step.
 23. The method of claim 21, further comprising moving the gas separation unit to the well site on a trailer.
 24. The method of claim 21, the removing step comprising removing CO₂ gas to form a sales gas stream comprising at least natural gas and CO₂, the CO₂ comprising less than 3 percent of the sales gas stream.
 25. The method of claim 21, further comprising: continuing the removing step until the concentration of CO₂ in the gases in the fluid flowing from the at least one wellbore is within a range specified by a buyer of the natural gas; and moving the gas separation unit from the well site to a second well site, or to a holding location for storage until the gas separation unit is to be moved to and used at a second well site. 